The growth of distributed energy resources (DERs) presents intrinsic challenges to electric utilities, from reliability to grid planning and rate design. And for nearly two decades, no state has done more to adapt utility regulation to those challenges than California.
The California Public Utilities Commission opened its first regulatory proceeding regarding DERs in 1998. Since then, the CPUC has led the nation in pushing utilities to plan for DER growth, operate their systems with more distributed resources, and share data with third-party providers.
But over that time, California’s DER proceedings evolved into a tangled web of dockets, difficult and resource-intensive for stakeholders to follow. A new commission document aims to change that, summarizing a more than a dozen DER proceedings into a seven-page DER Action Plan.
“The Action Plan is a roadmap for where we want to go with DER, the ways we can get there, and what we have to do to achieve the vision that we’ve laid out through 2018,” CPUC President Michael Picker told Utility Dive.
Picker, who became CPUC president after the resignation of Michael Peevy in 2014, saw “a great deal of creativity being unleashed” in the CPUC’s energy division when he arrived, but sensed that not every unit was moving in the same direction.
He asked the commission create a roadmap “to figure out which decisions needed to come in which proceedings.” Once the project was underway, the commission realized the information could be of use to stakeholders, and it became the DER Action Plan.
The plan covers three key areas: rates and tariffs; DERs on the distribution system; and DERs in wholesale markets.
If regulators can devise the right markets and rules, the payoffs could be huge. By 2020, DER could deliver $1.4 billion per year or more to California in net societal benefits, according to SolarCity calculations using an Electric Power Research Institute methodology and rate case data from Pacific Gas and Electric.
Technology and marketplace innovations will likely limit the Plan’s applicability beyond its 2017-2018 focus, Picker said.
“This is a strategy that allows us to walk, and then to jog, and then to run.”
The DER Action Plan
Many of the distributed energy rules under consideration in California are the product of legislation, the Action Plan notes, including mandates for the reform of utility distribution system planning, investment, and operations to include “time- and location-variant” rates to support DERs.
Senate Bill 350, a 2015 law that codified the state’s 50% renewable energy mandate, specifically requires an integrated resource plan (IRP) process (R.16-02-007) in which the CPUC is “to identify optimal portfolios of resources” to meet policy goals, including DERs.
That IRP process is outside the Action Plan’s scope, but is “the capstone of all this,” according to Picker.
“We’re shifting away from procuring individual resources,” he said. The intent is to create “a template that directs procurement by load serving entities in a way that improves reliability, reduces greenhouse gas emissions, and gives people a value for their expenditure as rate payers or as consumers.”
To get there, the DER Action Plan includes four stated purposes: defining a “vision” for DER policies; identifying ongoing CPUC activities regarding it; envisioning further CPUC actions for the vision; and putting in place a “DER steering committee” responsible for sustaining work toward that goal.
“The vision elements are where you are going, the continuing elements are what you’re doing, and the action elements are what you need to make sure the vision comes into being,” Picker said.
Among the topics covered by the “Rates and Tariffs” section are the TOU Rulemaking (R.15-12-012), the Residential Rate Design proceeding (R.12-06-013), the General Rate Case (GRC) Phase 2 proceedings (like A.16-06-013), the Net Energy Metering (NEM) successor tariff proceeding (R.14-07-002), and Rule 21 plans.
The “Distribution Planning, Infrastructure, Interconnection, and Procurement” section includes the Distributed Resource Plan (DRP) proceeding (R.14-08-013), reforms to the GRC Phase 1 proceeding (A.16-09-001), the Integrated Distributed Energy Resources (IDER) proceeding (R.14-10-003), interconnection directives (D.16-06-052), and the energy efficiency proceedings (R.13-11-005).
The “Wholesale DER Market Integration and Interconnection” section includes the Storage proceeding (R.15-03-011), the California Independent System Operator (CAISO) stakeholder processes, and the Demand Response proceeding (R.13-09-011).
Rates, tariffs and distributed energy
In the rates and tariffs section, the vision is “a continuum of rate options, from the simple to complex,” the Plan reports. The continuum would allow customers to make “informed choices” from among innovative, flexible, and timely rates.
Rate structures should include time-varying, cost causation, and DER capacity benefit factors, as well as keep rates affordable for customers who do not own DER.
The Plan calls for five actions by 2017, three by 2018, and one by 2019.
By 2017, a review of non-residential demand charges will produce DER-specific recommendations, a methodology for setting TOU periods will be developed, and a review of ongoing opt-in TOU residential pilots will be completed. A forum for work on rate and tariff innovation is also planned.
By 2018, pilots for residential default TOU rates will be implemented, analytical tools for DER valuation will be developed as part of the NEM successor tariff proceeding, and plans for helping customers take advantage of time-varying rates will be in place.
By 2019, mandated default residential TOU rates will be implemented.
From these many different rate profiles, the DER role in the marketplace will be clarified, Picker said.
“These are all things we are talking about in different proceedings and this teases out what were we thinking when we started down this pathway, what we really want to achieve, and the tools we need,” he said.
Distribution system planning & DERs
In the distribution section, the vision is to enable DERs “to meet distribution grid needs through a transparent, seamless planning and sourcing process,” the plan reports. The objectives are greater DER deployment, better system reliability, and reduced cost.
New tariffs and policies would remove disincentives to investor-owned utilities (IOUs) to deploy DERs, making procurement “ technology-neutral and competitively procured.” Valuation would then “accurately and impartially” reward all DER benefits and grid services.
System data would support and streamline DER interconnection through accurate and regularly-updated hosting capacity analysis and value information. DER markets would be enabled with necessary communications and cybersecurity technologies.
The first of the plan’s nine actions for this section was a new commitment to demonstration projects. Another was last year’s new study of societal impacts of DER.
The Action Plan calls for the commission to focus in 2017 on the locational value of DER, to finish work on a distribution system planning process and a grid modernization framework, and to begin looking at how Distributed Energy Resource Management Systems can support DER deployment.
In 2018, the Commission is scheduled to take up its landmark Integration Capacity Analysis (ICA) and develop guidelines for utility and utility-affiliate ownership of DERs. By 2020, the Plan expects advanced smart inverters to be operational and supporting DER grid integration.
The crucial efforts of both the Locational Net Benefit Analysis (LNBA) and ICA working groups are described in this section of the Plan.
“They describe how to determine locational value for DERs and how utilities can source them in the market,” said Scott Murtishaw, President Picker’s energy adviser. The groups offer "revolutionary” and “brand new” processes for obtaining the full value of DER and cutting ratepayer costs, he said.
The temporal and locational valuation of DERs is already a reality in California, according to Picker.
“We are wrestling with how we manage it,” he said. “The ICA tells us where we need to strengthen the grid to accommodate DER and the LBNA helps to figure how we actually reward DER at those locations.”
Wholsale markets & DER integration
The vision of DERs as grid resources requires them to be more visible, dispatchable, and cost-effective in wholesale markets. That means developing rules and procedures for compensating their multiple “stacked” services with individual revenue streams at the wholesale, distribution, and retail market levels.
In this vision, wholesale market rules and interconnection tariffs would support customer-based DERs, including electric transportation resources.
The first of this section's five actions will come this year with the study of how to reconcile the Federal Energy Regulatory Commission (FERC) transmission level regulatory jurisdiction and the CPUC distribution level jurisdiction.
In 2018, the CPUC will consider the eligibility of net metered resources in wholesale markets, plan streamlining of interconnection complications from transmission and distribution system authority overlap, and complete research needed to include vehicle-grid integration into the state’s transportation electrification policy. Work on EV rates will be ongoing.
CAISO’s distributed energy resources plan (DERP) will allow smaller resources to deliver value to its markets, Murtishaw said. It is not part of the Action Plan but an appendix notes that it will apply to most DER and all utility customers.
The jurisdictional complications are important, especially for battery storage, Picker noted. Consumers can use behind-the-meter storage or energy stored in the battery of an EV to moderate their own energy use or sell it to their utility or allow it to be aggregated and sold as a grid service to CAISO.
“The challenge is identifying the stacked values DERs can provide, quantifying that value, and then setting up a process to compensate them,” Picker said.
Stakeholder comments made on the draft version were “a reality check,” for the commission, Murtishaw said.
Comments filed with the commission from Southern California Edison (SCE) continue to reflect the utility’s concerns, said Spokesperson Jude Schneider.
The utility’s recent whitepaper “outlined a similar vision to accelerate the industry transformation” and this Action Plan can play “a key role,” according to SCE.
SCE endorsed the plan’s prioritizing of grid modernization to enable the use of more DERs for grid services.
“SCE is experiencing robust customer adoption of DERs – averaging 5,000 NEM applications each month,” its filing reports. But “the pace of DER deployment must be accelerated to achieve the state's ambitious carbon and clean air goals.”
SCE supported the commission's synchronizing with CAISO’s DERP work on jurisdictional issues and on aggregating DER into wholesale markets. Aggregation “is a new concept with the potential to greatly increase market participation from DERs, on the supply and demand side,” the utility wrote.
San Diego Gas & Electric (SDG&E) also stood by its filed comments, Spokesperson Amber Albrecht said. The filing called the Action Plan a “thoughtful approach” and “a well laid out roadmap.” But it also proposed improvements unanswered in the final version.
The plan does not adequately recognize “the changing landscape of the California energy market,” SDG&E argued. Forecasts of load, DERs, and energy efficiency growth could “strand existing investments,” the utility added. This could be accentuated by retail market innovations like Community Choice Aggregation.
Because these potential load impacts could drive up customer rates, the CPUC should scrutinize components of the Plan that do not share costs and benefits “equally across all customers.”
The need for “the ‘right’ rate design cannot be overstated,” the utility added. “There will likely be more change within the electric industry in the next ten years than in the past 100 years.”
Rate designs must avoid cost shifts and subsidies and provide accurate price signals, transparent incentives, customer options, and transition paths to minimize impacts and inform customers, the filing argued.
Like SCE, SDG&E recommended the commission prioritize grid modernization and, especially, funding for Distributed Energy Management Systems (DERMS). With DERMS in place, SDG&E argued, utilities can become Distribution System Operators and “manage the grid in a way to maximize the use of DER.”
Finally, the Plan should recognize “the critical role” of the IRP process but is “notably silent” on it, SDG&E said.
Picker took issue with that point, saying the final plan does acknowledge “critical links” between the Plan and the IRP proceeding and promises the results of that proceeding “will be incorporated.”
“This Action Plan will inform, and be guided by, IRP as that process takes shape,” he said.
Vendors and other stakeholder reactions
The recognition of the IRP as essential may be one reason Chloe Lukins, program manager at the Office of Ratepayer Advocates said her office “generally believes the commission is implementing ORA’s recommendations.”
EnerNOC VP Mona Tierney-Lloyd said her company stands by joint comments from demand response (DR) providers Comverge, CPower, EnerNOC, and Energy Hub that call for broader rate design changes.
Incentives are needed for both load modifying and supply-side resources to absorb renewables’ over-generation and to reduce demand when renewables’ generation falls off, she said.
“There should be appropriate recognition of the value of both increasing and decreasing demand and consumption to provide grid reliability services,” the DR providers argued.
They, like other commenters, argued the Action Plan “does not provide sufficient detail” on how outcomes will be achieved. They ask for reassurance the plan “does not duplicate or replace” the California Energy Action Plan and its mandated loading order that requires IOUs to procure energy efficiency and demand response ahead of all other resources.
Most of Vote Solar’s concerns remain “largely unaddressed,” according to Jim Baak, grid integration program director at the pro-solar nonprofit.
The final version shows “some progress” but still lacks “a vision for where this whole effort will lead and what role the utilities will have,” Baak said. “Specifically, the commission has not indicated whether the utilities will become Distribution System Providers or whether there will be distributed energy markets, as New York has done with their REV process.”
“One of the greatest barriers to animating and sustaining the market for DERs,” Vote Solar argues in its filing, is the misalignment of the IOUs’ financial incentives with DER deployment. This should be “a separate initiative, supported by the effort identified in the Integrated Distributed Energy Resources proceeding to address utility business models.”
Because the plan does not do so, Baak said, the barrier to a DER market “may ultimately result in missed opportunities for DERs and potentially higher fixed charges for customers with DERs.”
One of the central flaws in the valuation is its overemphasis on “avoiding distribution capital investments” as opposed to capturing the full range of DER values, he added. This misses the values of DER procured in the private sector and “outside the utility planning process.”
The failure to include work on the design of tariffs, incentives, programs, and markets that would drive private sector activity “severely limits DER growth potential,” Baak said.
Baak urged the commission to take up the discussion on locational data. Without it, “we will not be able to realize the full potential of DER.”
The difficulty inherent in writing the DER Action Plan is reflected in the parallel comments from Vote Solar and SDG&E. Both are concerned with shaping the market, but SDG&E’s emphasis is mechanisms that protect ratepayers from the impacts of a growing DER private sector. Vote Solar’s emphasis is mechanisms to drive the growth of the private DER providers.
The California Energy Storage Association (CESA) continues to see the plan an important “guide for California's regulatory work,” Executive Director Janice Linn told Utility Dive. The proceedings will consider "innovative tariffs" in the next two years that could enable greater use of DER-based non-wires alternatives in system planning.
CESA echoed the joint DR providers’ concern that this Plan’s use could impact the state’s statutory loading order. CESA also echoed concerns from SDG&E, the ORA, and others that the plan must be more explicit about how it will incorporate the IRP work.
ORA offered one of the most detailed critiques filed. The completed document’s simplified language and narrowed timeframe, from 2020 to a 2017-2018 focus, appear to confirm Lukins’ point that the final draft followed ORA suggestions. The Plan’s sections on research and development, on advanced inverters, and on DER management systems also reflect suggestions in the ORA filing.
ORA called for “a clear hierarchy of proceedings” to avoid duplications, conflicts, and omissions. This seems to be answered in the plan’s three distinct groupings, each with its own “elements.”
ORA approved of the Integrated Distributed Energy Resources (IDER) proceeding for procuring resources and planning infrastructure to meet the goals of the IRP and distribution planning proceedings.
Many ORA criticisms are directed less at the plan than what is missing in existing rate design proceedings. An example is ORA's call for “a clear vision” of how efficiency, demand response and distributed generation plans will to meeting goals set in the IRP, DRP, and IDER proceedings.
ORA stressed “affordability,” called for “marginal cost-based rates,” and for including “cost causation” in rates to meet SB 350 DER deployment goals. In general, it argued for the use of ongoing proceedings and general rate cases for work on rate innovation.
Staffers Matt Tisdale and Nick Chaset were instrumental in getting the Plan done, Picker said. “They herded the cats and the cats all now know where the dinner dishes are.”
The Action Plan remains a work in progress, he said, but it has already “helped shape the way people are using some DER and what they need to do to prepare for IRP process procurement.”
It has also clarified thinking about rate options as a continuum.
“Given the new technologies and different ways people are approaching this, we need to start thinking about many different rate options,” Picker said.
Finally, the Plan has moved the commission away from thinking about data as something that only needs to be more available to third party aggregators and private providers, Picker said. “The real question may be how to make it easier for customers to find their choices and help them realize they no longer need to see themselves as vassals in a vast, feudal system.”